I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Good morning, everyone, and thank you for joining us on our 4th quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer along with David Looney, Executive Vice President and Chief Financial Officer and Eric Hambly, Executive Vice President, Operations. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude non controlling interest in the Gulf of Mexico. Please keep in mind that some of the comments made during this call will be considered forward looking statements as defined in the Private Securities Litigation Reform Act of 1995.
As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussions of risk factors, see Murphy's 2019 Annual Report on Form 10 ks on file with the SEC. Murphy takes no duty to publicly update or revise any forward looking statements. I will now turn the call over to Roger Jenkins.
Good morning, Kelly.
Thanks to
everyone for calling in today. Before we get started reviewing our 2020 and Looking Forward segment of day to day, I would like to address the recent actions taken by the Biden Harris administration. Murphy, like all operators across federal lands in the United States is disappointed, but not at all surprised by recent actions. Unfortunately, as a matter of public policy, believe their efforts is misguided. U.
S. Emissions peaked over a decade ago in the United States and continue to fall every year. Growth in worldwide greenhouse gas emissions comes primarily from the Far East, Southeast Asia and Africa. These new initiatives will punish domestic producers and workers, but will not lower worldwide emissions. Ironically, any policy that includes the Gulf of Mexico actually hurts the carbon footprint as the Deepwater Gulf has the lowest carbon intensity of all of the E and P business.
Last week, the U. S. Department of Interior announced a temporary suspension of delegated authority for 60 days. It is important to note that this order does not limit existing operations under valid leases and provides a method for obtaining necessary approvals. There is potential for delay in consolidation of approval authority.
However, to date, we've been pleased with the progress and are moving forward. Murphy is well positioned to continue execution of our short term and long term projects, including Khaleesi, Mooremont Samurai and our non operated projects based on approvals in hand, discussions with our regulators and progress made in the last week obtaining actual approvals to conduct ongoing operations on current leases. We've also seen in the past 2 weeks over 20 approvals given for work in the Gulf of Mexico to not only us, but our peers. Yesterday, the White House announced a pause on new oil and natural gas leasing on federal land and waters, pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. This action is also not surprising.
Existing and ongoing lease work was not included in the announcement. The administration's recent actions have confirmed the viability of our company's strategy and increased the value of our diverse global portfolio. This includes large private U. S. Onshore acreage, both onshore and offshore Canada assets and a robust international exploration portfolio, including offshore Mexico, Brazil and Vietnam.
As you can imagine, there are many pieces here moving forward. Expect once the dust settles that permitting approvals will return to a process we can work with. It's not in the government's best interest to halt operations in the Gulf for a host of financial and legal reasons. Again, we have a diverse portfolio and all these actions are highly likely to increase oil prices, which would be in our favor over time. That's all I have on this comment today on these remarks, and return to Slide 2.
Murphy remained steadfast in our strategy despite the turmoil of 2020, maintaining our diverse portfolio while operating in a safe, sustainable and physically responsible manner. Our capital discipline leads to a targeted flatter oil production profile with additional free cash flow generation coming from the recently announced Tupper Montney development, along with long term price recovery scenario. We remain focused on our shareholders through our long standing dividend, our employees, contractors and communities by establishing and practicing our successful COVID-nineteen protocols. Our portfolio continues to span onshore and offshore locations in both U. S.
And Canada, which offers many advantages in today's Slide 3. Following the OPEC price war, Slide 3. Following the OPEC price war beginning of the COVID-nineteen global pandemic last year, we focused on a few primary areas to solidify the company and remain competitive over the long term with multi basin operations. We have completed a significant company wide reorganization, resulting in reduced G and A costs, as well as lowered our overall cost structure and capital program. Our focus on maximizing free cash flow and maintaining liquidity with the support of crude oil hedges and natural gas forward sale contracts led to the sanctioning of the low risk Tupper Montney development and reduced capital allocation toward growing shale oil production.
Additionally, we continue to support development plans for both long term deepwater Gulf projects as well as our international exploration program. Slide 4. Mercury produced an average of 149,000 barrels equivalent to date per day in the 4th quarter. These volumes include impacts totaling nearly 4,000 barrels equivalent from 2 subsea equipment issues with production expected to restart in the Q1 2021. The unplanned events in the Gulf of Mexico were partially offset by strong North America onshore performance.
Our cash CapEx totaled $111,000,000 for the quarter, inclusive of $1,000,000 in NCI spending. On an accrued basis, CapEx totaled $130,000,000 net to Murphy, excluding Kings Key. Prices continue to improve in the 4th quarter with oil realizations at an average of $42 the highest of course seen since quarter 1 and natural gas at 2.36 dollars per 1,000 cubic feet also far ahead of prior quarters. On Slide 5, our full year 2020 production averaged 164,000 barrels of oil per day. It was a dynamic year and we experienced a record breaking hurricane season following historically low prices resulting in industry wide production shut ins for a short period.
Overall for the year, we averaged nearly $38 per barrel for realized oil prices with 1.85 dollars per 1,000 cubic feet for natural gas. Cash CapEx for the year totaled $7.60 which included $23,000,000 of NCI CapEx.
On a
crude basis, CapEx totaled $712,000,000 excluding Kings Key and NCI spending as per our guidance. On reserves on Slide 6, our proved reserve base remains sizable at year end 2020 with $697,000,000 of barrels oil equivalent, comprised of 41% liquids and 51% proved developed. Our proved reserve life is maintained at more than 11 years. Overall, our total proved reserves were 13% lower from the year end 2019 due to 2 primary events. The first was a combination of lower SEC crude oil prices along with Murphy's shift in focus away from oil shale production growth, which resulted in transfer of Eagle Ford Shale and Kaybob Duvernay PUDs to probable reserves.
The change in capital allocation of the current 5 year plan reduced PUDs by over 100,000,000 barrels equivalent. Separately, the sanction of the Tupper Montney development in the 4th quarter resulted in conversion of probable reserves and contingent resources to proven undeveloped, totaling nearly 100,000,000 barrels equivalent. On Page 7, while total proved reserves are lower year over year, our North American onshore proved plus probable resource remained near 2,500,000,000 barrels oil equivalent. We maintain the ability to rebook our onshore shale PUDs with adjusted capital plan in the future if we decide to do so, as the reserve transfers were based on capital timing and not subsurface risk. As in any resource booking, it would also depend on prices, cost structure at the time and a 5 year planning cycle change.
Overall, Murphy continues to hold more than 3,400 undrilled locations across onshore North America. Further, our U. S. Onshore Eagle Ford Shale position is located on private lands. I'm now going to turn it over to David Looney, our CFO, and let him update us on some financial information.
David?
Thank you, Roger, and good morning. Slide 8. Murphy recorded a net loss of $172,000,000 or a $1.11 net loss per diluted share for the Q4 of 2020. After tax adjustments, including but not limited to, a non cash mark to market loss on crude oil derivative contracts and contingent consideration totaling $159,000,000 resulted in an adjusted net loss of $14,000,000 or a $0.09 adjusted net loss per diluted share. Slide 9.
Improving commodity prices led further strengthening in revenue for the quarter. Overall, our net cash provided by continuing operations rose to $225,000,000 in the 4th quarter, including a $13,000,000 cash outflow from a working capital increase. When combined with property additions and dry hole costs of $135,000,000 including $38,000,000 for Kings Key, we had positive free cash flow of $90,000,000 in the quarter. Regarding Kings Key, the producer and owner groups continue to make good progress on the array of legal documents and we look forward to a closing possibly within the next few weeks. For full year 2020, our net cash from continuing operations of $803,000,000 included a $39,000,000 outflow from working capital.
Property additions and dry hole costs of $859,000,000 including Kings Key spending of $113,000,000 resulted in a negative free cash flow of $56,000,000 for the year. If we exclude the Kings Key expenditures for the year, we would have had positive free cash flow of more than $55,000,000 We continue to maintain a high level of liquidity with $1,700,000,000 at year end, including $311,000,000 of cash and equivalents at December 31. With our focus on cost reduction measures throughout 2020, we've achieved significantly lower G and A with an approximately 40% reduction in full year cost from 2019. Lastly, Murphy continues to protect its future cash flow with the addition of 'twenty one and 'twenty two crude oil hedges as well as fixed price forward sales contracts for a portion of our Tupper Montney production through 20 24. Slide 10.
Liquidity remains a key focus for Murphy and our balance sheet remains strong with $1,400,000,000 available under our $1,600,000,000 senior unsecured credit facility as well as $311,000,000 of cash and equivalents as of December 31. We reiterate our goal of reducing our total debt level over time with excess cash flow. This reduced leverage will give us even more resilience through the inevitable commodity price cycles to come. With that, I'll now turn it back over to Roger.
Thank you, David. On Slide 12, as a company, we're responsible to the environment, employees and our stakeholders who have a long history of protecting all, in part due to our strong internal governance processes. I'm particularly proud of how quickly the team established COVID-nineteen protocols to maintain safe offshore operations. We had zero downtime or disruptions due to those efforts. Murphy achieved another year of low metrics, including 46 percent reduction year over year in total recordable instance.
We expanded our internal diversity inclusion practices and programs and maintained a program to aid impacted employees in times of need through our Disaster Relief Foundation, which we will use this summer with hurricane relief on the Louisiana coast. Our operations team continued their work on minimizing our environmental impact, such as building a new produced water handling system to recycle water and our sanctioned Tupper Montney project as well as utilizing bifuel hydraulic frac spreads on all well completions in Canada, which results in considerable CO2 emissions reductions. While smaller changes individually add up to a larger impact over time. On Slide 13, on sustainability. Last fall, we released our 2020 sustainability report, which features expanded disclosures and metrics.
A key highlight is our goal of reducing greenhouse gas emissions intensity by 15% to 20% by 2,030 from 2019. The report also outlines diversity disclosures, workforce development, employee engagement programs. Murphy has also expanded our HSE Board Committee to include oversight of corporate responsibility formed and we formed an ESG Executive Committee and created a new Director of Sustainability role. We've taken many steps and we continue to evolve and advance our sustainability efforts. On Slide 15 on the Eagle Ford Shale business, we produced 31,000 barrels equivalents per day in the 4th quarter comprised of 71% oil.
For the full year, production averaged 36,000 barrels equivalent per day with $197,000,000 of CapEx, which includes near $50,000,000 for field development as well. We brought online 25 operated and 10 non operated wells earlier in that year. The team continued their efforts on improving well performance and high grading production enhancing projects in facility and artificial lift optimization. Murphy is seeing an average base decline rate of 24% for all wells drilled prior to 'twenty one, which in our view is very well positioned. On Slide 16, on the Kaybob Duvernay project, the company produced 10,000 barrels equivalent oil per day in the Q4 comprised of 75% liquids and averaged 11,000 barrels equivalent per day for the full year.
Overall, Murphy spent $94,000,000 in CapEx during the year, including Placid Montney, Reagan Online 16 operated wells in Kaybob and 10 non operated wells in Placid. Also in 2020, Murphy completed its drilling program to hold all acreage, resulting in full discretionary future development. Most notable in the Q2 in the Kaybob East 15/19 pad, which is achieving significant results as our best wells in Kaybob Duvernay so far, ranking in the top 2% of all Murphy unconventional wells. Overall, it's competitive with our top producing wells in Karnes County and the Eagle Ford Shale. Slide 17, in the Tucker Montney, we produced $234,000,000 per day in the 4th quarter and averaged 238,000,000 cubic feet per day in the full year 2020.
Approximately $14,000,000 of CapEx was spent during the year to drill 4 wells with completions planned this year and ongoing. Additionally, the Tucker Montney plant expansion was completed during the Q4. Since our last earnings call, Murphy has added significant fixed price forward sale contracts at AECO Hub through 2024, which combined with improving basis differentials and higher prices as well as higher EURs can lead to stronger free cash flow generation. Slide 19, the Gulf of Mexico. Our assets there produced 63,000 barrels equivalent of oil per day in the 4th quarter, comprised of 78% oil.
Production volumes were impacted by nearly 4,000 barrels of oil equivalent per day on unplanned downtime due to 2 subsea equivalent issues in addition to previously guided hurricane downtime in the Q4. Full year 2020 production averaged 70,000 barrels of gold per day. Short term projects continue to progress with operating Cali Epsilon scheduled for 1st oil in the 2nd quarter, non operated wells in various stages of completions and tie ins, and we expect oil to begin flowing in the first half of the year to plan. In Gulf of Mexico Slide 20 on major projects, we remain on schedule with Kingski construction at 90% complete and drilling beginning in the Q2 for Kaleesi and Ormont Samurai Development. The non operated St.
Malo on Slide 22, in exploration, we participated in the latest OCS Gulf of Mexico lease sale during the Q4 and we were awarded and fully awarded 8 blocks with 5 prospects at a net cost of approximately $5,300,000 As a result, our Gulf of Mexico interest today totaled 4 exploration blocks and 15 key prospects at this time. On Slide 24, on our capital program, For 2021, Murphy plans to spend $675,000,000 to $725,000,000 and achieve production of 155,000 to 165,000 barrels equivalent per day. For the Q1, we've to 157,000 barrels of oil equivalent per day. Approximately 47% of our 2021 CapEx is allocated to offshore Gulf of Mexico with nearly all dedicated to the major long term projects that achieve first oil in 2022. Another quarter of our 2021 CapEx is budgeted for the Eagle Ford Shale with the remainder split between onshore continuing focus on high margin assets and our oil weighted portfolio resulting in free cash flow generation after our dividend.
On Slide 25. Our North American onshore capital budget is $265,000,000 in 2021 and is focused on maintaining flat production at Eagle Ford Shale with 170,000,000 team operated wells and 53 non operated wells as well as field development, which is 30% of the total spend. Approximately $85,000,000 is earmarked for newly sanctioned Tupper Montney development program to bring 14 wells online during the year. The remaining $10,000,000 of CapEx supports field development and maintenance in the Kaybob Duvernay and non operated Placid. Of note, our oil weighted shale drilling was more than 1400 locations in the Eagle Ford Shale and more than 600 in the Kaybob Duvernay.
Slide 26, in the Tupper Montney project, we're excited for this opportunity as the development brings to our portfolio. We're seeking we're seeing lowest basis differentials in 5 years. Beyond that, we've continued improvement in Murphy's well economics and EURs in the area, creating sustainable attractive cast carbon intensity in our portfolio. Lastly, the macroeconomics have shifted significantly in our favor in the last few years with additional takeaway capacity achieving necessary pipelines as well as construction beginning on LNG Canada project with a planned in service date of 2025. On Slide 27, the Tupper Monument asset has been strong proven resource with rising EURs in recent years and ever improving cost structure, while maintaining very low subsurface risk.
We've recently put in place additional fixed price forward shale contracts in 2024, approximately $215,000,000 through 2025. Slide 28. In the Q4, we formed into an attractive play opening trend for a 10% non operated working interest with Chevron as operator. The first well planned is the Silverback prospect and we will provide access and we will also be provided access to 12 blocks through our participation. On Slide 29, we continue to progress our various exploration projects and are excited with the optionality that the non operated position in Serquipe Alagros Basin in Brazil provides our company.
Murphy is working with partners to mature our drilling inventory and our partner plans to spread the 1st Brazil well in the second half of twenty twenty one. In the Salina Basin in Mexico on Slide 30, continue to advance our position there. We have many leads and prospects here and target spudding the 1st exploration well in late 2021 or early 2022. Overview of the LRP on Slide 32. A long term strategy of a dynamic plan to maximize cash flow while managing CapEx after dividend remains unchanged as is our commitment to a flatter oil production profile.
Our Tupper Montney development leads to an approximately 8% CAGR from 'twenty one through 'twenty four, while oil growth remains at 3%. Through this, Murphy will generate cumulative free cash flow after dividend at our base price scenario sizable debt reduction. As we began with our announcement in 2020 for a lower capital program, the average annual CapEx through 2024 is approximately $600,000,000 with 2022 being the peak year due to finalizing the major Gulf projects along with increased Tuppermint Montney development. Of course, we maintain a portion allocated to our exploration strategy with a target of drilling 3 to 5 wells per year. Slide 33 is to close out 2020 and lean into 2021.
Murphy is sticking with our priorities of managing CapEx to support a lighter production profile and combined with protective hedges, allows for maximum free cash flow generation, strong liquidity and debt reduction and long term price recovery, as well as consistently paying a dividend to our shareholders. Lastly, I want to extend my
Ladies and gentlemen, we will now begin the question and answer session. First question comes from Neal Dingmann at Truist Securities. Please go ahead.
Good morning, all. Riser, I appreciate your prepared comments on the federal lease and permits. I'm just trying to dive straight into that. Could you give your thoughts on just in ballpark, how long you anticipate that your current inventory could take you? And more specifically, what you all would eventually pivot towards if there was some type of ridiculous permanent federal band or and once your current assets are worked out?
Well, actually as I said, there's short term and long term things that we work on every day in the business. It's a business that requires communication with the regulator across several factors. We've continued to be able to do that during the suspension of authority period. We're very pleased with that. Also pleased with what's going on with non operated work on a day to day type basis, which in our remarks today, we talked about some subsea wells that are needed to be repaired and that work is progressing as per even with this suspension.
We're well positioned to start our Khaleesi, Walmont project and continue on. Actually, we are ahead of target on regulatory there and have more permits than you would normally have for development this time. The permits are given pretty close to the drilling date and historically been that way in the Gulf. So well positioned there. As far as a what would we do with some kind of scenario like that, I mean, I appreciate that question, but yesterday's did not mention anything about current leasing.
We're finding that everything that's ongoing like our project is being treated like an ongoing project and it's the way it's being treated and being worked today. There's regulatory work going on, on a normal business basis today in this building. And so naturally, if there were to be some wild outlandish moratorium, which didn't do well in the Macondo time for the government at all, We have a lot of flexibility. First step may would be, hey, let's just stop and have a lot more free cash flow and pay down our 22 notes with this matter and then continue on. It wouldn't be a need to rush in to go try to duplicate things that we own.
That's kind of our first step and it's quite helpful to us in that regard if we're able to get these projects back going again. Naturally, we have a big business. But in all in all, that's a pretty wild scenario and the work that we're doing today isn't pointing to that scenario in my view, Neil.
No, I agree with you. And then just my follow-up, I'll stick with the Gulf. I'm looking at that Slide 22 and it just really reemphasizes just how many opportunities you have there. Just wondering, Roger, what gets you? You have so many of these things when I'm looking at all the exploration projects, as you mentioned, prepared remarks, number of things coming on, not even this year, but already planned for next year.
I'm just wondering what sort of makes you most excited right now? Seismic advantage in that area. We also have a couple of opportunities near Frontrunner, Ninja that we're happy about because it's nearby. We have a very exciting well to drill at Cascade Chinook in the long run. It's a down thrown fault segment.
Major Wilcox plays have been very successful. It's a very big deal for us in the future, very large type of a well that's near production. And we're very happy to partner with Chevron in our new silverback area, which is adjacent as shown in the slide here, adjacent to some acreage, a new feature. This is we're very excited at Chevron again back to our strategy being a respected company that people want to work with. We're fortunate to be in a working relationship with a super major that's experiencing the Gulf.
So I feel really well positioned because that's sort of a company making thing at the right kind of working interest, but helps us derisk our blocks if that were to be successful. So those are the highlights there, Neil.
Very, very important. Thank you so much.
No, thank you.
Thank you. The next question comes from Don McIntosh at Johnson Rice. Please go ahead.
Good morning, Roger. Hey, good morning.
How are you doing?
Good. I noticed on the Eagle Ford spend for next year, dollars 170,000,000 but a little less than a third of that's going to be going towards what you call field development. I was hoping you could provide a little more color on what you're going to be building out there?
I'll have Eric get his expertise and talk to you all the way through that and everything you need about here.
Okay. When we build our capital program what we lump into field development is pretty much everything other than wells. So building pads, flow lines, pipelines, allocation separators, people costs, things like that. So it seems like a large number, but it really is more driven by the well activity. It's not like we're building a massive new facility.
We're also working on electrification, some other things involving ESG in this business all the time on improving our flaring and reducing always our emissions. We have a new takeaway of pipeline in Eagle Ford to further reduce flaring that we're excited about. So there's CapEx hook in those types of things as well that are required and needed and the right thing to do at this time.
All right. Thank you. And then for a follow-up on the subpromotiny, congrats on getting that Tinwell program sanctioned. But looking beyond that and kind of longer term with the 6% gas CAGR versus the or 8% versus the oil over the next kind of 3 or 4 years, what are you all seeing out there that you think might be stickier maybe from a demand perspective? I know you said basis has gotten tightened up the most it's been in 5 years.
Just kind of looking for some color on what you all are seeing?
Yes. If you look at the data, it was very variable on a very poor basis, very poor of which we did then did some off AECO type business to protect our risk, which worked very well for us at that time. Then the debottlenecking by TCPL, they claimed they were going to do all this capital work. They did the work, both East and West. And there was a time where it was difficult to get the gas to a summer storage facility there.
And now that they're needing more gas in the country and less capital available by Canadian junior players in Calgary, then the production has greatly dropped. And now we can get the gas to storage, which eliminates this very viable, very, very low poor summer month type productions and shut ins. Also TCPL had downtime through the years quite frankly. And because there's less 2 Bcf of less production, there's less downtime. So here we are with this big position, best lowest risk thing we ever had.
We started comparing it to low oil prices And then we decided this would be a great capital allocation for us also very, very good from a greenhouse gas intensity perspective. So we feel there's a better chance for oil to go to $60 and make a lot of cash flow in our oil flat production shale than it is for gas here to get $5 I'd say. Then we found a unique way to book the gas in hedges that was very advantageous to us and allows us to have almost book, if you will, free cash flow. Also these reserves are audited, completely audited by McDaniels in Canada and have been for a long time. Eric is a former executive involving reserve audit team, sort of the top of the line reserve work here, great operations, incredible ahead of it, hedging that we've done and really well positioned in there.
That's happened over time. Also in Canada, they have switched coal out and have less production and need the gas and get the storage. And we have LNG long term there, which we are of course very familiar with in Malaysia and offer and a lot of those folks involved with LNG we've worked with before and outstanding reputation to deliver gas in Canada, I mean in Asia over these years through LNG will help us in the
long run-in my view.
All right. Thank you for all that color.
The next question comes from Leo Mariani at KeyBanc. Please go ahead.
Good morning. Good morning, Leo.
Hey, guys. Just want to follow-up a little bit on some of those last comments. If I hear you right, it sounds like you guys are much more bullish on gas than oil over the next couple of years. And then maybe just kind of doing a little bit of a look back just on Q3, you guys were certainly planning on kind of ramping up Eagle Ford here in 2021 when I think some higher expected volumes when oil prices were closer to 40 and now we're kind of over 50 here today on oil and gas maybe hadn't done all that much in the last several months. It's a little bit better, but not as dramatic of an improvement.
I understand you guys had facility work and there's a lot more capacity now tougher and summer outlook looks better. But just wanted to kind of confirm, are you just more optimistic about gas in the next couple of years versus oil? And it looks like to you that the returns are tougher or just better now than Eagle Ford despite higher oil prices?
Well, it's not at all that way as far as the bullishness to oil. We still feel oil can go up and especially with all this regulatory. But what we're trying to do and what we said was to we want to plan our business on a flatter oil profile in shale, especially Eagle Ford. And because we're well positioned there with our high oil percent and very known customer in that area, selling of our oil is needed in that area. We feel that if we keep that flat and oil prices go up, we can make much more free cash flow.
And we're trying to get out of the debt business and add free cash flow and successfully handle that company. Also our folks in Eagle Ford have done a great job on maintaining base and base decline, which I think is very critical. So it's not that way at all. We see it's an increase in oil price as a way of keeping shale flatter and making more free cash flow, which is not uncommon supposedly by my peers. Now in Canada, price has been greatly improved, our cost structure improved.
We had like 15 different reasons why we needed to book that and do that. We're still only going to be making at when this project is full out around $500,000,000 a day. So it's not like we're turning all gas and making Bcfs of gas or anything like that. So it's all about as we said before a flatter profile with more free cash flow to significantly reduce debt and higher prices. And the Montney came along on top of that and you have to say for a project it's going to go from $240,000,000 to $500,000,000 and fooling around with $80,000,000 CapEx to do that really isn't that difficult and it's very capital efficient.
So it's more about a unique project that we have is in our phase to be successful with our flat profile with higher oil prices to have more free cash flow. It's that. It's nowhere around anti bullishness on oil prices or anything like that, Leo, really.
Okay. And obviously, you guys talked a little about your multi year ramp at Tupper, kind of 8% between now and 2024, pretty robust. You guys are talking a little bit more kind of flat to 3% on the oil side. Just how does the Eagle Ford participate once we get out of 'twenty one? And it looks like you're trying to maintain Eagle Ford in 'twenty one at 4th quarter.
Is there a ramp in 'twenty two, 'twenty three or 'twenty four? Or are you going to basically wait after Kings Key comes on to kind of reallocate CapEx? What's the long term plan for the Eagle Ford there?
Our plan today is again to have a flat profile in Eagle Ford to set it up to make it could probably make $500,000,000 to $600,000,000 free cash flow over a 4 to 5 year period and mid-50s oil price. And that's what we wanted to do today. That's our plan today. And it doesn't really have to do with Kings Key or anything like that. So again, our strategy, as you know, most of last year was this plan.
It just so happens that the Montney got so positive for us that we added it on with very little change in CapEx and improved all it was accretive to all our metrics, our covenant metrics, our free cash flow metrics. It's accretive to everything we did, so we executed on because our cost structure is so low. It's just really that, I believe.
Okay. That's good color. Maybe just on the Gulf of Mexico here, you guys talked about fairly significant downtime in the Q4. You talked about some downtime moving into Q1 as well. Could you kind of quantify what's baked into the Q1 guide in terms of the downtime here?
I was just kind of looking at your guidance, and I think you guys are saying your oil volume is going to be up around 3,000 barrels a day in the Q1, despite the fact that you had something like 18,000 BOE per day down in the Q4 through storms and whatnot. So I guess I'm just trying to figure out if there's a bunch of additional downtime in the Q1, I would have thought it would have been up more.
We were well positioned going into around mid December in the Gulf and very, very well positioned. We had 2 one off subsea events happen that require some equipment to be put offshore and repaired. 1 was an operated field and 1 non op. That is in works now to be done on both at different levels of completion and we have that in this quarter to be recovered. We also have some very nice wells being drilled at Lucius, operated now of course Oxy that we purchased through the Petrobras agreement through that formation of the JOA.
And so that will be coming online and we will be increasing production in the Q2 in the Gulf with all that. And that's where we are on that, Leo. It was a surprise, a couple of subsea events are being fixed. And we have wells coming on at Lucius as well, also our Caliote well that we mentioned and doing well.
Your next question comes from Arun Jayaram at JPMorgan. Please go ahead.
Good morning. Roger, I wanted to ask you about the 2021 to 2024 outlook that you've highlighted on Slide 32. You guys have provided an outlook of $600,000,000 in CapEx per annum with a little bit of higher CapEx in 2020 2 with the development projects. I was wondering if you could maybe help us think about the year to year trajectory from 2022 to 2024 in Q1?
Arun, if I want to give you a year over year trajectory, I'd put it on slide. I have it right here in my hand. In 4 years, we've seen 2 major price collapses in our business and recover back and guiding out year to year CapEx, I don't think it's a good idea. There's no secret that our CapEx this year midpoint of $700,000,000 is what it is and I think very well positioned to do what we're doing with that with all the money that we're spending that will not contribute to oil production this year or gas. And next year is going to be higher CapEx in this year and we're going to be dropping down pretty drastically after that.
So I prefer to leave it at that right now. A lot happens in a year, but that's our plan and through the color I provided on the prior calls about the flatter profile and more higher oil prices allowing more cash flow. That's our plan. But we I think the point here we're trying to make is that we've disclosed the CAGRs. We have our business that we talked about, our oil business, if you will, our offshore business, our Eagle Ford business and the Duvernay, of course, is almost 80% liquids with very, very high prices and doing well.
That business is slightly growing, which has been our plan for 9 months probably. And the growth is in the Montney because it's a unit of time to get into the Montney and book that and it was available to us. So through that though, with conservative oil prices through this 4 year period, we will have cash flow cumulative above our dividend in the low 40s or mid-40s at most. And in the mid-50s, we're going to
we can cut our debt
in half or more. And that's what we're trying to do, working on it.
Fair enough. And my second question is just regarding the Gulf of Mexico development program. You guys are sticking with the timeline around Khaleesi, Mormont, a semi first oil. Based on what we know today, Roger, and stop me if I'm wrong, you received 2 of the 10 permits for the program at Samurai, number 3 and number 4 per IHS. Can you walk us through and I think the rig arrives in April, but do you get started at Samurai and just wait for the incremental permit approvals?
And do you think that we could see some permit approvals during this 60 day, call it, time out from the DOI based on some of your commentary that you mentioned earlier?
Thanks, Arun for that. It's nothing I don't know where the 10 well thing is coming from. We have a 10 well commitment on a rig to do any kind of work we want for a certain price in the Gulf of Mexico. This is a 7 well Phase 1 development. Phase 1 meaning for the next few years, I think there's another couple of wells beyond 23 or something like that.
There's 4 existing wells in the ground out there. They've been drilled and they're cased and logged everything. There's 3 wells. When I talk about this, it's Colicie, Mormon and Samurai, which we work as one continuous field. We have partners that are different in those that not matter at this time.
Four existing wells, 3 new wells to be drilled and completed. So you're correct, on a public website, we do hold 2 drilling permits today. You can't get the completion permit till the wells are drilled. Completion permits often lag drilling permits because the drilling permit is a lot more complex and has been. It's nothing new, all the proper documentation.
So it would be not the norm at all to have all this approved. And I think we're well ahead to have what we have now because we are starting the work in April. And I'm not going to comment on the permits we get. They know we don't need them with our schedule, if you will. They know where the rigs are.
They run the business. They regulate the business. We have a great relationship with the regulator. Also, we're a very, very good operator in the Gulf and carry great standing on spills. We haven't had a spill in the Gulf in over 4 years, a great safety record, an incredible record as to instance of noncompliance, one of the leading companies.
So I believe that all helps. And like I said, we're well positioned here and would not have been now we have submitted all these permits. And as a matter of fact, the completion permits have been come back to us for comments. It's quite awesome to ask questions on these permits. So they're engaged in an ongoing field and in an ongoing way.
And there's documentation also when you start a development like this with the government to outlay to them that you're going to develop this and you have to provide that you've got a signed rig contract and the signed ability to put in the pipelines and they're part of an overall process that they know about and we are relying on and they know this. And so it's going as we would anticipate And we like I said, based on it's only 1 week, but based on what we've seen, we're working with it and moving our business forward. Great. Thanks a lot for that color, Roger. Thank you.
Your
next question comes from Brian Singer at Goldman Sachs. Please go ahead.
Thank you. Good morning. Good morning.
Good morning. To follow-up further on the Tupper Montney gas, you indicated you've gotten the EUR up to 21 Bcf. And I wondered, A, is that a function of the longer laterals or can you add more color on what's changed beyond that? And then B, is that kind of the going forward expectation for wells and at the 11,000 the expectation for lateral length on a longer term basis.
I'll let Eric handle that for you, Brian, and I'll come back to any other question you might have.
Brian, the well performance is driven by 2 things, longer laterals and also better recovery per lateral foot or lateral meter. So if you go back to the beginning of our asset there, we had 4 BCF wells that were about 5,000 foot laterals and now we have 21 DCF wells that are about 11,000, 12,000 foot. Our plan is to have about 3000 meter laterals for this development program. And so you're getting a combination of improved performance per lateral foot plus longer laterals. Going forward, we don't expect to lengthen our laterals from what we've been doing over the last couple of years.
Great. Thank you. And then my follow-up is with regards to Slide 32, the slide that focuses on that 2021 to 2024 plan. Can you talk a little bit more about what's baked into that? Is there a wedge at all baked into either CapEx or production, assuming any exploratory discoveries from here?
Is there any kind of risking on federal land timing and timing of projects? And can you talk about Vietnam and whether there's anything there that's baked in from either a CapEx or production perspective?
There's absolutely no exploration success in the plant. There never has been. And that's why this talk of delaying and permitting really doesn't do anything to our company. And as we talked about earlier, we have 15 really good prospects in the Gulf on acreage that we hold, entered into another project with a super major acreage that they hold today. And again, the executive order yesterday didn't really get into that.
Vietnam is a field development that is absolutely in place. It's between $80,000,000 and $100,000,000 barrel project. It can be developed. We've submitted the field development plan and working with the regulator there. We're used to working with regulators offshore all over the world and projects.
It's about the same. As a matter of fact, people may not realize this, but most international areas copy the U. S. Regulatory. We're very used to it.
And but it's a little slower there for that. And when they get that, we could put that into our plan and look at replacing something. But today, it's not in the plan. This is what we own today, what we're doing. We're very knowledgeable about it.
We do not have a delay built in on Khaleesi, Montmartre, nor Saint Malo. I feel comfortable with what I understand about the projects not to do that at this time. I'd say we're ahead of schedule on Khaleesi, Moremont and Samurai, which gives us better flexibility. If anything, we're ahead there. So in that position in the schedule would allow for flexibility in my view based on what I know today is the way I feel about it, Brian.
Great. Thank you.
No, thank you.
Thank you. The next question comes from Gail Nicholson at Stephens. Please go ahead.
Good morning, Gail.
Good morning, Roger. Hey, I was curious on the farm in opportunities. I feel like people don't fully appreciate your track record and the interest that you guys garner in that. Can you just talk about how that farming opportunity have changed over time and what you kind of see potentially in the future there?
Well, there are not many operators in the Gulf at our size and nimbleness, if you will. And we have we've been in the Gulf for a long time. We're a top 4 operator on gross operated production in the Gulf, well known. All of our executive team primarily worked super majors before. We have relationships with super majors.
We respect it in that way. And there's a lot of 54 exploration blocks ourselves. Can you imagine how many BP Shell and Chevron have? And going forward, there's been no mention of stopping that at this point, could be, but it hasn't been that way. We will be able to look at all kinds of things in the Gulf going forward, the way the regulation and executive order is at this time.
The issue with some of these things is a very nice thing here. It is a rank opportunity and a new play, But all my friends really don't like me to talk about it too much. So the more the better and better things I do, my operator friends don't like me to speak about it. So I'm caught up in that a little bit. I'm not going to blow that because I want to keep those relationships and continue to form into these very unique company making opportunities such as Silverbacks, such as Sergipe Alagosis and other places where we work.
So sometimes that slide wouldn't show what exactly we'd like to say, but that's the business we're in and that's okay and we get along with them well and there's a mutual respect by super majors with our company and we're proud of it.
Great. And then just looking at
the Montney, you guys have a very impressive all in cost up there, about $1.44 per Mcfe. I was just kind of curious, as you move into a more steady state development program, do you think that there's room for incremental cost improvement over time?
I'll let Eric answer that
for you, Gabe. We have a significant percentage of our operating costs that are not variable with production rate. So as we fill the gas plant, as Roger mentioned, we'll get up to about 500,000,000 cubic feet at peak in that project. We'll see the per barrel or per Mcf cost go down. So I would model the cost to be in terms of dollars per year nearly flat, maybe slight increase with a little bit more cost for new wells, but very minor.
Okay, great. Thank you.
The next question comes from Paul Cheng of Scotiabank. Please go ahead.
Hey, good morning, Paul. Hey, guys. Good morning.
I wanted to ask just curious that in your budget, I suppose that you have a range of oil price you built in. Can you share with us what's that? And how the program may change based on the changes in oil price, if oil price is much higher than that range? Or you are pretty much fixed to that and say, okay, if the higher oil price are just going to generate more free cash flow. So how should we look at that program?
We don't usually disclose our pricing. We have here a base price that's over the next 4 to 5 years, I'd describe as at best mid-40s starting low to mid. We have a recovery case that reaches into the 50s in 2 or 3 years, mid-50s, never more than that. It is our plan today to not increase this CapEx and to have the higher oil prices deliver more cash flow to our company balance sheet to be used as we see fit to reduce debt at the appropriate and proper time. So no discussions here on a different capital plan, on anything like that today, Paul, going on here at Murphy.
Perfect. And for modeling, it's really great economic. So right now, your plan is get to 500, but you do have a lot of inventory. So is there any plan or any opportunity that you expand that beyond that? Have you talked to the gas plant operator and see whether that is going to see more infrastructure being built?
We have a unique agreement when we sold this business for this for that provider of the midstream work to build plants at a fixed price or a way of negotiating a price, which we consider to be well positioned. We did that here and there's ample area to do it. It can be it can continue to go in $250,000,000 increments as much as we want there. Right now, we're going through a 'twenty four, 'twenty five period to keeping it 500 in our current plan and then reevaluate if we want to go more, but we certainly can. And I wouldn't see us increasing it in this plan because again of all the talk this morning about trying to keep our plan like it is and make more free cash flow.
The real unique thing about Montney that may not be understood is our is that infrastructure is in place. It's been very successful, this plant, from an uptown perspective. And all drilling right in the middle of where we've already built infrastructure. It's in place and we're drilling right in the middle of where we've already built infrastructure. It's extremely capital efficient here and very unique.
But we needed we were doing really well on all our work, but the price just changed, the diffs just changed, everything changed and you see that you have to make a move and we had a great plant and a great midstream operator. It's going extremely well and we moved on and went ahead.
Walter, how does that process work in terms of the let's say who make the decision going to expand the PAG, is it a midstream operator or that you guys make a request and then sign a contract with them, they will increase it or that you sold it from there?
No, we'll have to mutually agree on the next one to work and we will and I can't imagine why they wouldn't want to continue because their subs are through and that we're a nice capitalized company for them to be partners with.
Two final quick questions. First, that for the 2 December and time downtime in the Gulf of Mexico, is that fully fixed the problem? And what is the
I know there are boats in the Q1.
Boats in the field working on the problems today or this week and the impact of that it's already in our guidance as to when we think the wells will come back on. And do you know the impact, Eric?
Middle of the quarter.
Middle of the quarter should be all be flowing and it's in our guidance.
And so we should assume it's roughly about 5,000 barrels per day? No, no, no. We're trying to look at what is the incremental benefit that in the Q2 we should assume when this coming back?
It's in the plan. It wouldn't be that it's not that much. The Q1 current guidance would not be that magnitude of downtime from these wells, probably about 3,000 off the top of my head.
Okay. And then finally that you already have a pretty sizable hedging program for 2021. Should we assume you are pretty offset or that you will look for opportunity to increase that further?
In 2021, no, at this time. In 2022, we have done some hedges, which is disclosed in our release and working on options to review that, but not settled in on that now because feel like we're well positioned with our cash, feel like we're well positioned on our liquidity and really taking a look at the additional hedging for 2022 at this time and haven't made a decision yet
on that.
Next question comes from Josh Silverstein at Wolfe Research. Please go ahead.
Good morning, Josh.
How are you doing?
Hey, good morning. Thanks guys. I'll just follow-up on the some of the hedges there. You mentioned the $47 number this year to cover the CapEx and the dividend. I'm wondering if that excludes the hedges since those were put in place at $43 And then maybe if you can just give us some trajectory in that longer term outlook.
I imagine the $47 may go higher next year since the peak spending. But then where would that go to in the 'twenty three, 'twenty four time period as the bigger projects fall off?
Our number here would include the hedges and all calculations. And the follow on question, I'm sorry, in the future, we have some 22 hedges that's disclosed here today. That's all we have. And I have no hedging done prior to that. We do like to hedge some of our production.
It depends on how much free cash flow and where oil goes and where our liquidity is as to that percent that we would want to do. Historically have not been that high of a hedger, but reviewing that in great detail. Does that answer your question, Josh?
Yes. Sorry, the second part of it was just the trajectory of where the 47% may go to next year. My guess is maybe it goes up, but then as you go into 2023 2024, where would that 47 fall towards?
Well, I wish I knew that. I wouldn't be here talking to you. So I believe myself there's not a lot of liquidity. We're in backwardation now. Severely, we have seen periods of time before COVID where the backwardation just continues to move to the right and the curve looks the same.
We're like I said earlier today, we have a base price of low 40s to mid 40s over 20 to 25 period in our mind. We're able to cover our dividend and all these big projects during that period cumulatively, very happy about that. And we're able to handle that without a difficulty because we have a lot of projects in the next couple of years that today as Brian asked a question earlier, there's no exploration CapEx today. So we should be well positioned to handle whatever that will be. I do believe oil will get into the low 50s personally to mid-50s after vaccines and COVID and the rebound of demand.
But there's a long way to go about that. That's what I believe personally, but that doesn't mean that we're planning to have to have that or anything like that.
Okay. Yes, I'll follow-up on that. And then can you just talk about the Eagle Ford program as well? It's heavily operated in the first half and then you're kind of reliant on non operated activity in the back half of this year. Will this basically help kind of stem the decline from not having much activity in 2020?
And I'm just curious how the volumes are being risked for the back half given the shift from operators in and out?
Yes, you're right about our operated program. We have 19 wells to come online in the year, 16 in the Q1, 3 in the 2nd quarter. And then our non operated program is 2nd and third quarter weighted. The non operated program that we're participating in is quite a large number for us. It works out to be the equivalent on a working interest basis of about 10 wells.
So those are material for us relative to our historical non op contribution. The programs are all well underway and I don't expect any kind of timing issues or uncertainty around the timing of delivery for the non operated because we're working closely with operators. We know what they're doing. They're executing quite well.
Yes, the commitment non op positions of BPX. We have incredible team. We visited with them in detail last year. They purchased this asset for a lot of money. They're very serious about developing it and we feel pretty good about that non op right now, Josh.
What's somewhat unique about the program is quite a few of the non operated wells that will come online this year have already been drilled. So they're mostly completion activities in 2021. And production expectation for Eagle Ford is flat at about 30,000 barrels a
day. Great. That's helpful. Thanks guys.
All right, Josh. Thank you. I believe that's your last question at this time. Is there one more? Okay, everyone.
We're going to return back to work here. We appreciate everyone calling in and we'll be seeing you in our next quarterly result. Appreciate all your questions and help and thanks for calling in. Appreciate it. Bye.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and we ask that you please disconnect your lines.